When an oil well is first drilled and completed, the fluids, such as crude oil, in the wellbore may be under natural pressure sufficient to produce on its own. In other words, the oil rises to the surface without any assistance. In many oil wells however and particularly those having been established for years, natural pressure can decline to a point where the oil must be artificially lifted to the surface. For artificially lifting oil, subsurface pumps are located downhole in the well below the level of the oil. A string of sucker rods extends uphole from the pump to the surface to a pump jack device, or beam pump unit. A prime mover, such as a gasoline or diesel engine, or an electric motor, on the surface causes a pivoted walking beam of a pump jack to rock back and forth, one end connected to a string of sucker rods for moving or reciprocating the string up and down inside of the well tubing.
As is known, a string of sucker rods operates the subsurface pump, with the typical pump having a plunger that is reciprocated inside of a pump barrel by the sucker rods. The barrel has a standing one-way valve adjacent a downhole end, while the plunger also has a one-way valve, called a travelling valve. Alternatively, in some pumps the plunger has a standing one-way valve, while the barrel has a traveling one-way valve. Relative movement alternatively charges the pump chamber, between the standing and travelling valves, with a bolus or increment of liquid and then transfers the bolus of liquid uphole. More specifically, reciprocation charges a displacement pump chamber between the valves with fluid and then displaces the fluid out of the chamber to lift the fluid up the tubing towards the surface. The one-way valves open and close according to pressure differentials across the valves.
Pumps are generally classified as tubing pumps or insert pumps. A tubing pump includes a pump barrel which is attached to the end joint of the well tubing. The plunger is attached to the end of the rod string and inserted down the well tubing and into the barrel. Tubing pumps are generally used in wells with high fluid volumes. An insert pump has a smaller diameter and is attached to the end of the rod string and run inside of the well tubing to the bottom. The non-reciprocating component is held in place by a hold-down device that seats into a seating nipple installed on the tubing. The hold-down device also provides a fluid seal between the non-reciprocating barrel and the tubing.
The hold down device may be assembled to provide for either, or both of, a top hold down configuration or top anchoring of the downhole pump, or a bottom hold down configuration or bottom anchoring of the downhole pump.
A top anchored rod pump is generally used in shallower, e.g., 5000 feet or less, sandy, low fluid level, gassy, or foamy wells, and has some benefits to those well known to the pump industry, while the bottom anchored rod pump has benefits in deeper wells.
The benefit and disadvantages of both top and bottom anchored pumps would be well known to those familiar with rod pump selection procedures and will not be discussed in further detail here.
Volumetric efficiency of a pump is reduced in wells that have gas. The displacement chamber between the standing and traveling one-way valves fails to fill completely with liquid. Instead, the displacement chamber also contains undissolved gas, air or vacuum, which are collectively referred to herein as “gas”.
The gas may be undissolved from the liquid (so called “free gas”), or it may be dissolved in the liquid (so called “solution gas”) until subjected to a drop in pressure in an expanding displacement chamber, wherein the gas comes out of solution. Gas takes the place of liquid in the displacement chamber, permitting a compression of the gassy fluid in the chamber and diminishing the displacement and lifting of liquid therefrom. The presence of gas in the displacement chamber reduces the efficiency of the pump, and lifting costs to produce the liquid to the surface are increased. This condition is known as “gas interference”.
The presence of too much gas in the displacement chamber can completely eliminate the ability of the pump to lift liquid. This is because the gas in the displacement chamber prevents the contents therein from being compressed to a high pressure sufficient to overcome the hydrostatic pressure above on the traveling valve. This condition is known as “gas locked”, and is a type of gas interference. In other words, the pump can become gas-locked when a quantity of gas becomes trapped between the traveling valve and the standing valve balls. Hydrostatic pressure above the traveling valve ball holds the ball in a seated position, while the pressure from the trapped gas will hold the standing valve ball in a seated position. With the balls unable to unseat, pumping comes to a halt with reduction or cessation of liquid production and other related issues.
In common field practice, a common method to break a gas lock in a conventional pump is to adjust the spacing of the pump setting, placing the bottom of the stroke into an interference state during reciprocation, and tap or impact the pump hard on the down stroke. This is done in an effort to jar the travelling valve open so as to break a gas lock. Hitting the pump to open the valves causes damage to pump components and the rod string. The adjustment of the pump requires a service visit and the extent of the tap is not always appreciated at the surface when the impact actually occurs one or more kilometers downhole. Further, rather than have service personnel return multiple times in response to repeated gas locking, a pump might actually be left configured to tap bottom continuously, damaging the sucker rods, rod guides, pump plunger and barrel.
Other attempts to solve the gas lock problem have concentrated on the valves, and the compression of a gas in the displacement chamber. One typical attempt is to remove the oil pump or the plunger from the barrel, and release the trapped gas. This can be time-consuming and interrupts pumping operations.
Operating the pump in a gas locked condition is undesirable because energy is wasted in that the pump is reciprocated but no fluid is lifted. The pump, sucker rod string, surface pumping unit, gear boxes and beam bearings can experience mechanical damage due to the downhole pump plunger hitting the liquid-gas interface in the displacement chamber on the down stroke. Loss of liquid lift leads to rapid wear on pump components, as well as stuffing box seals. This is because these components are designed to be lubricated and cooled by the well liquid.
Gas locking, and implementation of the above-mentioned solution for overcoming same, not only damages the pump and stuffing box, but can reduce the overall productivity of the well. Producing gas without the liquid component removes the gas from the well. The gas is needed to drive the liquid from the formation into the well bore.
Still another problem arises in the Texas Panhandle of the United States, where some oil fields have a minimum gas-to-oil ratio production requirement. In other words, both gas and oil must be produced. Many gas wells are unable to produce gas at their full potential because the downhole pumps are unable to lift the liquid, as the pumps are essentially gas locked.
Still another problem arises in stripper wells, which are wells that produce ten barrels or less of liquid each day. Stripper wells are low volume wells. The output from a stripper well is produced into a stock tank on the surface. Separation equipment, which separates the gas from the well, is not used because the production volume is too low to justify the expense of separation equipment. Produced gas is vented off of the stock tank into the atmosphere, contributing to air pollution and a waste of natural gas.
Still another problem arises in wells with little or no “rat hole”. The rat hole is the distance between the deepest oil, gas and/or water producing zones and the plugged back, or deepest depth of the well bore. Conventional downhole pumps cannot pump these wells to their full potential due to the low working submergence of the pump in the fluid. The low submergence results in both liquid and gas being sucked into the displacement chamber. If insufficient volumes of liquid are drawn into the chamber, the pump becomes gas locked. In low volume wells, the common practice is to shut the pump off for a period of time to allow sufficient liquid to enter the well bore. But, in wells with little or no rat hole, shutting the pump off has no effect because the liquid level is too low. Deepening the well bore is typically too expensive. While these wells do contain oil, it cannot be produced with known pumps.
There are also many wells which produce fluids having a high gas content. The pumping efficiency of conventional pumps, as hereinabove discussed, is considerably reduced, and pumping action can be completely blocked. While a liquid is substantially incompressible, hydraulically opening the check valves during the reciprocating pump stroke, a gas is compressible. Thus, gas located between the traveling check valve and the standing check valve can merely compress during the down stroke without generating sufficient pressure to open the traveling valve. No liquid is then admitted above the valve to be lifted during the up stroke and the pump is gas locked. This problem is aggravated in large bore pumps, where considerably more internal volume in the displacement chamber is available for gas accumulation, with concomitant low pressurization during compression.
In the past, it has been suggested to remedy such gas locking condition by preventing gas from reaching the pump. One way this was accomplished was by using an annulus below the pump inlet. However, in order to implement such a remedy, accurate data is required about the generally unknown formation characteristics. Furthermore, the fluid reservoir characteristics of such formations change with time, requiring constant adjustments to the pump installations. As such, the annulus method of preventing gas from reaching the pump is neither practical nor effective.
Such failures to completely fill the chamber are attributed to various causes. In a gas lock situation or a gas interference situation, the formation produces gas in addition to liquid. The gas collects at the top of the chamber, while the liquid is at the bottom, creating a liquid-to-gas interface. If this interface is relatively high in the chamber, then gas interference results. In gas interference, the plunger, on down strokes, descends in the chamber and hits the liquid-to-gas interface. The change in resistances causes a mechanical shock or jarring. Such a shock damages the pump, the sucker rods and the tubing. If the liquid-to-gas interface is relatively low in the chamber, gas lock results, wherein insufficient pressure is built up inside of the chamber on the down stroke to open the plunger valve. The plunger is thus not charged with liquid and the pump is unable to lift anything. A gas locked pump, and its associated sucker rods and tubing, may experience damage from the plunger hitting the interface.
In a pump off situation, the annulus surrounding the tubing down at the pump has a low fluid level, and consequently a low fluid head is exerted on the barrel intake valve. In an ideal pumping situation, when the plunger is on the upstroke, the annulus head pressure forces annulus fluid into the chamber. However, with a pump off condition, the low head pressure is unable to force enough fluid to open the valve and completely fill the chamber. Consequently, the chamber has gas, air or a vacuum therein. A pump in a pump off condition, as well as its associated equipment, suffers mechanical shock and jarring as the plunger passes through the liquid-to gas interface. A restricted intake can also cause pump off.
There is therefore a need for apparatus and methodologies that can effectively address gas lock/gas-interference in downhole reciprocating pumps.
Further to the foregoing, pump valves are designed for hostile environments, as they are subject to high pressures, high temperatures and corrosive fluids. The valves include a valve seat and a ball. The valve seat is a ring having a lapped, or shaped, surface for receiving the ball. When the ball engages the seat, the valve is closed. When the ball is disengaged from the seat, the valve is opened. Differential pressure moves the ball into or out of engagement with the seat.
For example, traveling valve assemblies are designed to allow the fluid that has entered the pump on the previous upstroke to pass through it with minimal pressure differential created during the down-stroke cycle of the pump. This is because, as the pressure differential increases, weight from the sucker rods directly above the pump is required to force the liquid through the plunger, and too much weight will cause them to buckle slightly and to come into contact with the inside of the tubing string, causing wear on the tubing string and on the sucker rods. It is therefore desirable to lower the force required to move the plunger through the fluid, not only to increase pumping rate and overall system efficiency, but to reduce wear.
An improperly guided ball in either valve will have difficulty seating, resulting in improper closure and leaking through the valve. Ball cages are used to constrain the movement of the ball and ensure a properly working valve, and are well-known in the art. The cage limits the movement of the ball axially along a narrow path and/or prevents the ball from oscillating and causing excessive wear. The tolerance between the ball and the inside side walls of the cage is small in order to minimize side-to-side movement of the ball. In addition, the cage provides openings around the ball for fluid to flow. See for example U.S. Pat. No. 6,830,441 to Williams.
Some wells produce relatively large quantities of sand. As the sand flows through the valve, it tends to accumulate and cause a loss in efficiency in pumping fluid to the surface, for example by choking off fluid flow, or by interfering with the ability of the ball to reseat and seal the valve, to release from the valve seat or to find the valve seat.
The ball and seat components used in both the traveling valve and the standing valve are exposed to excessive wear as a result of a number of factors, including the turbulent flow of fluids at high pressures. The turbulence leads to uncontrolled movement of the ball in the valve cage, or rattling side-to-side, eventually causing damage to both the ball and valve cage. Several attempts have been made to minimize rattling within ball check valves. See for example U.S. Pat. No. 6,899,127 to Swingley which describes methods that are relatively effective in minimizing rattle, but that also increase friction and therefore result in a decrease in the kinetic energy of the liquid flowing through the valve and an increase the pressure drop across the valve with all the disadvantages associated therewith.
Eventually, pump components need to be replaced as a result of being exposed to excessive wear and damage. In the past, valve cages have been equipped with hardened liners, in order to increase valve cage life. However, hardened liners can be expensive.
Valve cages commonly comprise guides, which may be formed either of hard metal or of elastomer pieces fixed within the cage. While elastomers are useful for wear aspects, they are not usually structural per se. Elastomer guides are difficult to assemble in the structural aspect of the cage and in lock in place. Unless pins or clips are used as locking means, it has been necessary to distort the guide pieces to insert or remove them.
There remains a need in the art for a pump valve that minimizes sand accumulation in the valve, that maximizes the flow capacity of the fluid of the cage, minimizing pressure drop across the valve, that minimizes the effects of travelling ball movement without causing additional friction, that maximizes the suspension time of solids within the fluids, which enhances flow capability of the fluid through the cage and through the tubing string, that further reduces or eliminates wear, avoids using guides, and that maximizes efficiency or operational capacity of the pump.